1. Field of the Invention
Embodiments of the present invention generally relate to artificial fluid-lift mechanisms within a wellbore. More particularly, embodiments of the present invention relate to progressive cavity pumps within the wellbore.
2. Description of the Related Art
To obtain hydrocarbon fluids from an earth formation, a wellbore is drilled into the earth to intersect an area of interest within a formation. The wellbore may then be “completed” by inserting casing within the wellbore and setting the casing therein using cement. In the alternative, the wellbore may remain uncased (an “open hole wellbore”), or may become only partially cased. Regardless of the form of the wellbore, production tubing is typically run into the wellbore (within the casing when the well is at least partially cased) primarily to convey production fluid (e.g., hydrocarbon fluid, which may also include water) from the area of interest within the wellbore to the surface of the wellbore.
Often, pressure within the wellbore is insufficient to cause the production fluid to naturally rise through the production tubing to the surface of the wellbore. Thus, to carry the production fluid from the area of interest within the wellbore to the surface of the wellbore, artificial lift means is sometimes necessary. Some artificially-lifted wells are equipped with sucker rod lifting systems. Sucker rod lifting systems generally include a surface drive mechanism, a sucker rod string, and a downhole positive displacement pump. Fluid is brought to the surface of the wellbore by pumping action of the downhole pump, as dictated by the drive mechanism attached to the rod string.
One type of sucker rod lifting system is a rotary positive displacement pump, typically termed a progressive cavity pump (“PCP”). These pumps typically use an offset helix screw configuration, where the threads of the screw or “rotor” portion are not equal to those of the stationary, or “stator” portion over the length of the pump. By insertion of the rotor portion into the stator portion of the pump, a plurality of helical cavities is created within the pump that, as the rotor is rotated with respect to the pump housing, cause a positive displacement of the fluid through the pump. To enable this pumping action, the surface of the rotor must be sealingly engaged to that of the stator, which also typically is an integral part of the housing. This sealing provides the plurality of cavities between the rotor and stator, which “progress” up the length of the pump when the rotor rotates with respect to the housing. The sealing is typically accomplished by providing at least the inner bore or stator surface of the housing with a compliant material such as nitrile rubber. The outermost radial extension of the rotor pushes against this rubber material as it rotates, thereby sealing each cavity formed between the rotor and the housing to enable positive displacement of fluid through the pump when rotation occurs relative to the rotor-housing couple.
Rotation of the rotor relative to the housing is accomplished by extending the sucker rod string, which is rotatably driven by a motor at the surface, down the borehole to connect to one end of the rotor exterior of the housing. At the lower end of the pump, an inlet is formed for allowing production fluid to flow into the production tubing, and at the upper end of the pump, production tubing extends from the pump outlet to a receiving means on the surface, such as a tank, reservoir, or pipeline.
Often before, during, or after the course of producing hydrocarbon fluid from the area of interest, one or more fluid treatments must be performed to remedy production problems. Effecting fluid treatments involves forcing treatment fluid into the formation, possibly into the area of interest in the formation. The fluid treatment may involve, for example, fracturing the formation using a fracturing fluid to allow improved draining of the reservoir within the area of interest or introducing inhibitors or functional additives into the formation to prevent paraffin, scale, corrosion, or excess water production.
To perform fluid treatment on the formation, pumps are required to overcome bottomhole pressure within the wellbore and force the treatment fluid into the formation. Currently, the pumps utilized to effect treatments are truck-mounted pumping units, usually cement pump trucks, which must be mobilized to the well site when fluid treatment is necessary and connected to the production tubing to pump fluid downhole within the production tubing and into the formation.
Using the truck-mounted pumping units to treat the formation is expensive, as the equipment is costly to rent for each day in which its use is desired. The truck-mounted pumping units may cost more than a million dollars each, so that significant fees are charged to rent the pumping units. Treatment of the formation with the truck-mounted pumping units is especially costly when fluid treatment operations are necessary which are most effective when utilizing low flow rates of treatment fluid to pump large volumes of treatment fluid over long periods of time.
An additional cost of treating the wellbore using truck-mounted pumping units lies in the hazardous nature of some of the chemicals employed for well treatments. These hazardous chemicals may inadvertently contact operators of the truck-mounted pumping units, creating a safety issue as well as increasing the cost of the well treatment due to additional safety costs.
Furthermore, additional cost is incurred using the truck-mounted pumping units to treat the formation because in order to operate the pumping units, the PCP must be pulled out of the wellbore (and then re-inserted into the wellbore after the treatment). Removing the PCP from the wellbore and again placing the PCP within the wellbore add to the well treatment price tag the cost of operation of a workover rig, which may require rental fees of $500 or more per hour of use.
Due to the sometimes prohibitive cost of treatment of the formation using the truck-mounting pumping unit, the duration of each fluid treatment is frequently cut short, such that maximum production during a period of time between treatments is not attained because the well is never effectively treated. Moreover, because wellbore treatment sometimes becomes too expensive using the truck-mounted pumping units and because the returns expected from the wellbore are not sufficiently high to justify treatment of the formation by the treatment fluid, the well may be shut down without realization of the full potential of the well production. At the very least, the high cost of treatment when using the truck-mounted pumping units decreases the profitability of the well.
Another problem with the use of truck-mounted pumping units at the surface of the wellbore is that chemicals used in treating the formation must be created from their constituents at the surface of the wellbore for pumping downhole. Some chemicals are time-sensitive and are more effective early upon their creation from the constituents; therefore, these time-sensitive chemicals may be rendered ineffective or less effective after the chemicals have traveled from the surface of the wellbore all the way downhole into the area of interest.
There is therefore a need for more cost-effective apparatus and methods for pumping treatment fluid into a formation. Further, there is a need for more cost-effective apparatus and methods for pumping treatment fluid into a formation which has been equipped with production equipment. There is an additional need for apparatus and methods for maximizing the effectiveness of time-sensitive chemicals utilized to treat the formation.